Oil and gas recovery from subterranean formations has been done in a number of ways. Some wells initially have sufficient pressure that the oil is forced to the surface without assistance as soon as the well is drilled and completed. Some wells employ pumps to bring the oil to the surface. However, even in wells with sufficient pressure initially, the pressure may decrease as the well gets older. When the pressure diminishes to a point where the remaining oil is less valuable than the cost of bringing it to the surface using secondary recovery methods, production costs exceed profitability and the remaining oil is not brought to the surface. Thus, decreasing the cost of secondary recovery means for oil from subterranean formations is especially important for at least two reasons:                (1) Reduced costs increases profitability, and        (2) Reduced costs increases production.        
Many forms of secondary recovery means are available. The present invention utilizes gas lift technology, which is normally expensive to install, operate and maintain, and often dangerous to the environment. Basically, gas lift technology uses a compressor to compress the lifting gas to a pressure that is sufficiently high to lift oil and water (liquids) from the subterranean formation to the surface, and an injection means that injects the compressed gas into a well to a depth beneath the surface of the subterranean oil reservoir.
Since the 1960's gas lift compressors have used automatic shutter controls to restrict air flow through their coolers. Some even had bypasses around the cooler, and in earlier models some didn't even have a cooler. Water wells employing free lift do not cool the compressed air used to lift the water to the surface. Temperature control at this point has never been considered important other than to prevent the formation of hydrates from the cooling effect of the expanding lift gas. Therefore, most lifting has been performed with gas straight from the compressor. The heat of compression in this gas is not utilized effectively and is rapidly dissipated when the lift gas is injected into a well.
Compressors for this service are expensive, dangerous, require numerous safety devices, and still may pollute the environment. Reciprocating compressors are normally used to achieve the pressure range needed for gas lifting technology. Existing reciprocating compressors are either directly driven by a power source, or indirectly driven via a hydraulic fluid. While both are suitable for compressing lifting gas, most prior art reciprocating compressors are costly to operate and maintain. Moreover, existing reciprocating compressors are limited to compressing gases because they are not designed to pump both gas and liquids simultaneously and continuously.
Existing compressors use many different forms of speed and volume control. Direct drive and belt drive compressors use cylinder valve unloaders, clearance pockets, and rpm adjustments to control the volume of lift gas they pump. While these serve the purpose intended, they are expensive and use power inefficiently compared to the present invention. Some prior art compressors use a system of by-passing fluid to the cylinders to reduce the volume compressed. This works, but it is inefficient compared to the present invention.
Another example of wasted energy and increased costs and maintenance is in the way the compressing cylinders are cooled in prior art compressors. All existing reciprocating compressors use either air or liquid cooling to dissipate the heat that naturally occurs when a gas is compressed. The fans and pumps in these cooling systems increase initial costs, and require energy, cleaning, and other maintenance. Prior art reciprocating compressors also require interstage gas cooling equipment and equipment on line before each cylinder to scrub out liquids before compressing the gas.
Another example of the inefficiency of prior art technology relates to current means for separating recovery components. Existing methods employ separators to separate primary components, then heater treaters to break down the emulsions. In some cases additional equipment is required to further separate the fluids produced. In each case, controls, valves, burners and accessories add to the cost, environmental impact and maintenance of the equipment.
Prior art compressors require additional equipment to pump the fluids produced from an oil and gas well from the wellhead through the pipeline to gathering or separation stations. In remote field applications, this additional equipment can be both environmentally hazardous and financially expensive. Such applications usually require such additions as “Blow-cases” or pumps. The present invention is capable of pumping these fluids directly, automatically, and at much lower cost.